Combustion of fuels such as coal, coke, natural gas or oil typically results in the presence of pollutants in the combustion flue gas stream resulting from the combustion process or derived from impurities present in the fuel source. Electric utility power plants that burn coal are a significant source of such combustion process air pollutants, but other stationary fuel-burning facilities such as industrial boilers, waste incinerators, and manufacturing plants are also pollution sources.
The primary air pollutants formed by these stationary high temperature combustion sources are sulfur oxides (e.g. SO2 and SO3), also called SOX gases, and nitrogen oxides, also called NOX gases, both of which are acid gases. Other combustion pollutants of concern in these combustion flue gases include other acid gases such as HCl and HF, Hg (mercury), CO2 and particulates. These individual pollutant components from stationary combustion sources have been subject to increasingly more stringent regulatory requirements over the past three decades, and emission standards are likely to be tightened in the future.
The removal or significant reduction of SOX and NOX contaminants, as well as other acid gases and elemental mercury, requires an integrated air pollution control system. Such integrated air pollution control systems represent a particular challenge in situations requiring retrofitting of first-time or additional or enhanced pollution control measures, e.g., older coal-fired electric power plants without any desulfurization measures or power plants with SOX controls requiring modifications for control of NOX gas emissions.
Nitrogen oxide or nitric oxide (NO) and smaller amounts of nitrogen dioxide (NO2) are the normal constituents of NOX contaminants formed in the combustion of fossil fuels like coal, coke and oil. The presence of NOX in a flue gas stream discharged to the atmosphere can result in a “brown plume” and is a contributor to ground-level ozone pollution (“smog”) and to acidifying nitrate deposition.
The wet scrubbing desulfurization techniques utilized for SOX removal from combustion flue gas are largely unsuccessful for removal of NO that is also present since the latter has low water solubility and is not amenable to aqueous alkali desulfurization scrubbing techniques. Although NOX formation can be controlled to some extent by modifying combustion conditions, current techniques for NOX removal from combustion flue gas normally utilize post-combustion treatment of the hot flue gas by Selective Catalytic Reduction (SCR) or Selective Non-Catalytic Reduction (SNCR)
The Selective Catalytic Reduction procedure utilizes a catalytic bed or system to treat a flue gas stream for the selective conversion (reduction) of NOX to N2. The SCR procedure normally utilizes ammonia or urea as a reactant that is injected into the flue gas stream upstream, prior to their being contacted with the catalyst. SCR systems in commercial use typically achieve NOX removal rates of 80-90%, but improved catalyst systems reportedly provide over 90% removal rates.
The Selective Non-catalytic Reduction procedure is analogous to SCR except that no catalyst is employed in the treatment of a flue gas stream with ammonia or urea for the selective reduction of NOX to N2. High treatment temperatures are required for the reduction reaction in SNCR, in the absence of the catalysts used in SCR systems. SNCR systems are favored for retrofit of smaller electric power utility plants because of their simplified installation and modest equipment requirements. Drawbacks to commercial SNCR systems are their requirement of very high and narrow temperature ranges to effect conversion of NOX to N, which often results in undesirable reaction byproducts, and their NOX removal rates of only 30-70%.
Many individual approaches are described in the prior art for the removal of specific SOX and NOX components. In actual commercial practice, the engineering challenge is the design of an integrated air pollution control system that can be retrofitted to existing fossil-fuel fired electric utility plants that are in need of updated or upgraded pollution controls for one or more of SO2, SO4, NO, NO2, Hg, HCl, HF, CO2 and particulates. Since individual electric utility plants are rarely alike, retrofit systems need to be adaptable to the specific requirements and needs of the electric utility plant being modified.
The present invention provides an air pollution retrofit system that is particularly well suited to (but not limited to) improving the performance of removing NOX in SNCR-treated combustion flue gas streams, utilizing a NOX reduction reagent. The novel NOX treatment system of this invention is not taught in prior art treatments for abating SOX and NOX contaminants in combustion flue gas streams.
U.S. Pat. No. 4,213,944 of Azuhata et al. (Hitachi) discloses a process for removing nitrogen oxides from a hot gas stream containing the same by adding a reducing agent, preferably ammonia, and hydrogen peroxide into hot gas stream at a temperature of 400-1200° C. to decompose the nitrogen oxides to nitrogen gas and water. The hydrogen peroxide is added concurrently with the ammonia and is said to increase the activity of the ammonia, particularly at gas temperatures of 400-800° C., by decomposing the ammonia to make it reactive with the NOX. Sufficient hydrogen peroxide is added with the ammonia so that excess unreacted ammonia is also decomposed.
A NOX treatment technique analogous to that described in the Azuhata patent involves treatment of a combustion flue gas containing NOX with ammonia and hydrogen peroxide and is described by D. A. Cooper in “The Influence of Ammonia and Hydrogen Peroxide Addition on NOx Emissions in the Flue Gas Channel of a 16 MW Coal-fired Fluidised Bed Combustor,” Journal of the Institute of Energy, vol. 61, no. 447 (1988), pp. 78-84.
U.S. Pat. Nos. 5,120,508, and 4,783.325 of Jones (Noell) disclose methods of converting NO to NO2 in a flue gas stream by injecting a gas containing a peroxyl initiator and oxygen into the NO-containing gas stream. The peroxyl initiator is preferably propane but may also be other hydrocarbons or hydrogen peroxide or hydrogen. The resultant NO2-containing gas stream is then treated in an absorption section to remove NOX and SOX with a dry sorbent such as nahcolite or trona, the dry sorbent being captured in a baghouse before the treated gas stream is discharged to the atmosphere.
U.S. Pat. No. 5,670,122 of Zamansky et al. (Energy & Environmental Research) discloses a method for removing NO, SO3, CO, light hydrocarbons and mercury vapor (Hg) from combustion flue gas by injecting into the gas stream atomized droplets of either hydrogen peroxide or a mixture of hydrogen peroxide and methanol, to convert the respective gas contaminants to NO2, SO2, CO2 (for the CO and light hydrocarbons) and HgO. The treatment is carried out at a gas temperature of about 377° C. to about 827° C., and the reaction products are subsequently removed in a downstream scrubbing operation. The treatment also may be carried out in combination with SNCR NOX reduction technology, with the SNCR-treated combustion gas stream being treated downstream with the H2O2 or H2O2/CH3OH injection treatment. The method is also described by Zamansky et al. in Preprints of Papers, American Chemical Society (ACS), Div. of Fuel Chemistry; Journal Vol. 40; Issue No. 4; Conference 210, Natl. Meeting of the ACS, Chicago, Ill., 20-25 Aug. 1995, pp. 1039-1044.
U.S. Pat. No. 6,676,912 of Cooper et al. (NASA) discloses a method of removing NO from stationary combustion gas streams by injection of H2O2 into the gas stream to oxidize NO to NO2 and HNO3 and HNO2, which species are more readily recovered via aqueous wet scrubbing. The nitrogen acids and residual NO2 are then removed via wet scrubbing with water or an aqueous alkaline medium or via passage of the flue gas stream through a particulate alkaline sorbent in a baghouse. The method may optionally include a preliminary flue gas desulfurization scrubbing step to remove SO2, prior to the H2O2 injection. U.S. Pat. No. 6,676,912 of Cooper et al. is hereby incorporated by reference for its disclosures about the reaction of H2O2 and NOX and related reactions.
U.S. Pat. No. 8,147,785 of Pfeffer et al. (FMC) describes a method for removing residual unreacted ammonia (ammonia slip) that is present in a combustion flue gas stream that has been treated via SCR or SNCR NOX treatment systems using ammonia or urea. The flue gas stream is treated downstream of the SCR or SNCR operation with aqueous hydrogen peroxide to remove residual unreacted ammonia.
The present invention provides a method for the removal of NOX in a SNCR system that enables the removal of NOX from the gas stream at reduced operating temperatures and that does not require use of ammonia as reducing agent.